Penn Virginia GP Holdings, L.P.

 

Filed by Penn Virginia GP Holdings, L.P. pursuant to Rule 425 under the

Securities Act of 1933 and

deemed filed pursuant to Rule 14a-12 under the Securities Exchange Act of 1934

Subject Company: Penn Virginia GP Holdings, L.P.

Commission File No.: 001-33171


Penn Virginia Resource Partners, L.P
American Association of
Individual Investors
Philadelphia Chapter
10/26/2010
NYSE: PVR
www.pvresource.com


2
Forward-Looking Statements
Certain statements contained herein that are not descriptions of historical facts are "forward-looking" statements within the meaning
of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.
Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or
implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:
the volatility of commodity prices for natural gas, NGLs and coal; our ability to access external sources of capital; any impairment
write-downs of our assets; the relationship between natural gas, NGL and coal prices; the projected demand for and supply of natural
gas, NGLs and coal; competition among producers in the coal industry generally and among natural gas midstream companies; the
extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves; our ability to
generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders;
the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees’ ability to
satisfy their royalty, environmental, reclamation and other obligations to us and others; operating risks, including unanticipated
geological problems, incidental to our coal and natural resource management or natural gas midstream businesses; our ability to
acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party
pipelines on satisfactory terms; our ability to retain existing or acquire new natural gas midstream customers and coal lessees; the
ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts
for such production; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated
start-up dates of our lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas
midstream business; environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural
gas; the timing of receipt of necessary governmental permits by us or our lessees; hedging results; accidents; changes in
governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with
respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of current and future
litigation regarding mine permitting; risks and uncertainties relating to general domestic and international economic (including
inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks);
and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.
Additional information concerning these and other factors can be found in our press releases and public periodic filings with the
Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2009.  Many of
the factors that will determine our future results are beyond the ability of management to control or predict.  Readers should not place
undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof.  We undertake no
obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result
of new information, future events or otherwise.


3
Diversified, Relatively Low-Risk Asset Base
Strategically Located Coal Reserves and Midstream Assets
Stable and Predictable Coal Royalty Business
Solid Balance Sheet and Attractive Yield
Stable Cash Flows and Distribution Coverage
Well
Positioned
to
Capitalize
on
Partnership
Momentum
&
Industry
Trends
Hedged Midstream Business with Growing Fee-Based Volumes
Key Investment Highlights


4
Current Structure
Penn Virginia
Resource Partners,
L.P.
(NYSE: PVR)
Public
Unitholders
32.7 MM
Common Units
60.4% LP interest
Penn Virginia
GP Holdings, L.P.
(NYSE: PVG)
Public
Unitholders
39.1 MM
Common Units
100% LP interest
Penn
Virginia
Resource
GP, LLC
100% ownership
2% GP Interest
and Incentive
Distribution Rights
37.6% LP interest
19.6 MM PVR Common Units
Notes:
1)
Chart displays simplified organizational structure
2)
Units outstanding and ownership interests are rounded
approximations
Penn Virginia
Operating Co., LLC
and its subsidiaries


5
Coal royalty
business,
not
coal
mining
Managed coal properties since 1882
Controls 829 MM tons of high quality coal
reserves (24 year R/P ratio)
Long-term leases with experienced operators
Ancillary businesses include coal services,
timber and gas royalties
Coal & Natural Resource Management
~ 2/3 of 2009 Adjusted EBITDA
(1)
Natural Gas Midstream
~ 1/3 of 2009 Adjusted EBITDA
(1)
$185 million of 2009 Adjusted EBITDA
(1)
Traditional gathering and processing business
Assets are located in attractive natural gas
basins with long-lived reserves
4,118 miles of pipelines
6 processing facilities
400 MMcfd of capacity
Average throughput volume 332 MMcfd in
2009
(1)
Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to net income and cash flow from operations
Overview


6
Coal & Natural Resource Management
San Juan
Basin
Northern
Appalachia
Illinois
Basin
Central
Appalachia
Coal reserves located in major supply basins
Access to major coal hauling railroads and
inland waterways
Close proximity to power generation facilities
Gathering systems located in major gas basins
Reserves in Oklahoma, North Texas and East
Texas are moderately declining and long-
lived
Significant growth potential from Marcellus
Shale
Crossroads
Arkoma
Panhandle
North Texas
Thunder Creek
Hamlin
Natural Gas Midstream
Marcellus
Crescent
Strategically Located Assets


Coal and Natural
Resource Management
7


8
~ 2/3 of 2009 Adjusted EBITDA
(1)
(1)
Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to net income and cash flow from operations
(2)
Does not include June 2010 acquisition of 10 millions tons of Pittsburgh Seam reserves.  With that acquisition, the N. Appalachia R/P ratio is 8.8 years
Coal & Natural Resource Management
33.0
603.9
18.3
Central
Appalachia
5.0
37.4
7.5
San Juan
Basin
34.9
163.9
4.7
Illinois Basin
6.2
23.4
3.8
Northern
Appalachia
(2)
R/P
Ratio
(years)
Proven /
Probable
Reserves
(MM tons)
2009 Lease
Production
(MM tons)
Region
24.2 years
R/P Ratio:
828.6 MM tons
Proved / Probable Reserves:
34.3 MM tons
2009 Lease Production
Coal Production & Reserves


9
Coal –
Attractive Long Term Fundamentals
EIA
(1)
forecasts that coal:
usage will continue to increase for next
25 years
will continue to be the dominant fuel for
electric power generation in the U.S.
will retain its cost advantage as the
cheapest energy source
(1)
Annual Energy Outlook 2010 (March 2010), Energy Information Administration (EIA)
Coal
Liquid Fuels
Natural Gas
Other
0
20
40
60
80
100
120
140
U.S. Energy Supply Composition By Primary Source
Fuel Oil
Natural Gas
Steam Coal
0
5
10
15
20
25
Coal
Petroleum
Natural Gas
Nuclear
Other
0
1000
2000
3000
4000
5000
6000
Energy Prices
(2)
U.S. Electrical Generation By Fuel Type
(2)
Prices paid for energy by Electric Generation Sector as reported by EIA


10
Coal Royalty vs. Coal Operator
Coal royalty –
not a coal mining operation
Historical Coal Prices vs. Coal Royalty Revenue
Majority of our royalty payments (82%) are based on the higher of a percentage of the gross
sales price or a fixed price per ton
Our lessees generally sell their coal under long-term fixed-price contracts (1 –
5 years),
which provides cash flow stability
Contracts with our lessees are long-term, with an average life of 10 –
15 years
No direct exposure to mine operating costs and risks or reclamation costs
Minimal maintenance capital expenditure requirements
Coal Royalty Business -
Stable and Predictable
High
Low
Reclamation Exposure
High
Low
Social Costs
(e.g. benefits, black lung)
High
Medium
Reinvestment Requirements
Variable
High
Cash Flow Stability
Variable
High
Operating Margins
Coal Operator
Coal Royalty
Characteristic
0
20
40
60
80
100
120
140
0
5
10
15
20
25
30
35
40
Quarterly Coal Royalty Revenue
Central Appalacia
Illinois Basin


Consists of a combination of surface and
underground mines located in KY, VA and WV
Lessees customers are primarily electric
utilities
Coal is higher quality, lower sulfur
Proximity to East Coast ports make these mines
an ideal source of exports
Central Appalachia (73% of Reserves)
Illinois Basin (20% of Reserves)
Comprised of properties in southern Illinois and
western Kentucky
Acquired 169 MM tons of reserves in the Illinois
Basin beginning in 2005
The installation of scrubbers by Eastern and
Midwestern utilities has increased demand for
the high sulfur coal in the Illinois Basin
Primary Coal Basins
11


Northern Appalachia (3% of Reserves)
San Juan Basin (4% of Reserves)
Northern Appalachia holdings consist of the
Federal and Upshur properties
Reserves are 100% owned and 98% have been
leased to operators
Our Lee Ranch property is located in the San
Juan Basin of northwestern New Mexico and
contains only surface coal mines
Increased production from 2006 to 2007,
whereas statewide coal production dropped
Other Coal Basins
12


13
Changes
in
Coal
Reserves:
2002
2009
Coal Production
Reserves
by
Type
2009
Net
Royalties
by
Region
2009
Reserves
by
Region
2009
Coal –
Operations
492.8
571.3
(235.5)
0
200
400
600
800
1000
         Reserves        
12/31/01
       Production     
2002-2009
       Acquired       
2003-2009
828.6
0
5
10
15
20
25
30
35
40
2004
2005
2006
2007
2008
2009
Central Appalachia
San Jaun Basin
Illinois Basin
Northern Appalachia
Central
Appalachia
69%
San Juan
Basin
14%
Illinois
Basin
11%
Northern
Appalachia 6%
Central
Appalachia
73%
San Juan
Basin
4%
Illinois
Basin
20%
Northern
Appalachia 3%
Steam
89%
Metallurgical
11%


Fees charged to lessees for
use of coal preparation and
loading facilities
JV formed in July 2004
Fee-based revenues
Predictable cash flows
Services
5% of Coal & NRM Net Revenue
(1)
Approximately 243,000 acres
of forestland in Kentucky,
Virginia and West Virginia
Premium quality hardwood
primarily used for furniture
Timber
4% of Coal & NRM Net Revenue
(1)
In October 2007, we
purchased oil and gas
royalties located on 165,000
acres in eastern Kentucky
and southwestern Virginia
Almost all of our oil and
gas royalty interests are
associated with leases of
these properties
Oil & Gas Royalties
2% of Coal & NRM Net Revenue
(1)
Services, Timber & Oil & Gas Royalties
14
Represents 2009 Coal & NRM revenue less Coal Royalty expenses
(1)


Natural Gas
Midstream
15


16
~ 1/3 of 2009 Adjusted EBITDA
(1)
(1)
Adjusted EBITDA is a non-GAAP financial measure. See Appendix for a reconciliation of Adjusted EBITDA to net income and cash flow from operations
Natural Gas Midstream Overview
47
80
8
Crossroads
8
20
AMIs
with Range Resources
and a private E&P company
Marcellus
18
N/A
134
North
Texas
13
N/A
78
Arkoma
224
260
1,681
Panhandle
516
Hamlin
22
40
1,701
Crescent
375
N/A
588
Thunder
Creek
(25% JV)
2009
Volume
(MMcfd)
Processing
Capacity
(MMcfd)
Gathering
Pipeline
(Miles)
System
332 MMcfd
2009 Avg. System Throughput Vol:
400 MMcfd
Natural Gas Processing Capacity:
4,118 Miles
Gathering Pipeline:
Natural Gas Midstream Systems


17
Significant organic fee-based growth potential from Crossroads, Thunder Creek and
Marcellus project (initial start-up in late 2010 / early 2011)
Target hedging 50-60% of remaining commodity-sensitive volumes over 2 years
Currently, 60% of 2010 and 58% of 2011 price-sensitive volumes are hedged
Additionally, many gas purchase / keep-whole contracts contain a processing fee floor
Volumes by Contract –
2004
Volumes by Contract –
2009
Since entering the midstream business, we have focused on reducing commodity price
risk:
Acquiring fee-based businesses (North Texas and Thunder Creek)
Pursuing green field projects backed by fee-based contracts (Crossroads and
Marcellus)
Converting a portion of existing keep-whole contracts to fee-based or POP
Hedged Midstream Business with
Growing Fee-Based Volumes
Fee-
Based
14%
Keep-
Whole
52%
Percent-of-
Proceeds
34%
Fee-Based
19%
Keep-
Whole
28%
Percent-of-
Proceeds
53%


18
Gas Rig Count vs. Natural Gas Production
Lower 48 State On-Shore Gas Production
Oil-to-Natural Gas Price Ratio
Source: Energy Information Administration, Baker Hughes, and Bloomberg
Our assets are well positioned to benefit from
increasing activity in emerging resource plays:
Granite Wash
Marcellus Shale
Haynesville Shale / Horizontal Cotton Valley
Attractive processing economics are expected to
persist
Well Positioned Asset Base
0
200
400
600
800
1000
1200
1400
1600
1800
50
52
54
56
58
60
62
64
66
Rig Count
Production
0
2
4
6
8
10
12
14
16
18
20
Shale gas drives future
production growth
0.0x
5.0x
10.0x
15.0x
20.0x
25.0x
1990
1995
2000
2005
2010
2015
2020
2025
2030
2035
Conventional
Shale Gas
Coalbed
Methane
Oil Associated


19
Gathering system in the Anadarko Basin of
Texas and Oklahoma
Comprised of a number of major gathering
systems and compressor stations
Beaver / Spearman plants –
200 MMcfd of
inlet capacity
Sweetwater plant –
Acquired in July
2009,
60 MMcfd of inlet capacity
Approximately 203 producers pursuant to
332 contracts
Positioned to capitalize on the development
of the Granite Wash
Overview
Operating Statistics
Processing Plants
3
Processing Capacity (MMcfd)
260
Gathering System Length (miles)
1,681
Panhandle System


20
Crossroads
Gathering system in Oklahoma’s
Sooner Trend
Consists of 1,701 miles of pipeline
and 15 related compressor stations
Crescent
processing
plant
NGL
recovery plant with capacity of
40 MMcfd
Wells are generally low-volume and
long-lived with large NGL quantities
Crescent
Thunder Creek Gas Services
Hamlin
Arkoma
North Texas
Gathering system stretching over
West Central Texas with the Hamlin
processing plant located in Fisher
County, Texas
Consists of 500+ miles of pipeline
and 8 related compressor stations
Hamlin plant –
20 MMcfd capacity
Consists of three separate stand-
alone gathering systems in
southeastern Oklahoma’s Arkoma
Basin
Two systems are 100% owned,
third system is 49% owned
Average 2009 throughput volume
of 13 MMcfd
Purchased 25% JV interest in
Thunder Creek from Kinder Morgan
Energy Partners (April ‘08) in
Wyoming’s Powder River Basin
Devon Energy owns the other
75% interest
100% fee-based model
Average 2009 throughput volume of
375 MMcfd
Located in the southeast portion of
Harrison County, Texas
Anchored by a long-term
commitment under a fee-based
arrangement
80 MMcfd of inlet capacity
Centered around 5 major producers
Positioned for growth from
Haynesville Shale
Acquired gas gathering and
transportation assets in the Barnett
Shale play in the Fort Worth Basin
134 miles of gathering pipeline
Approximately 240,000 acres
100% fee-based revenues
Potential to increase revenues
through addition of processing,
treating and other services
Natural Gas Midstream –
Other Systems


21
AMI with Range Resources in Lycoming, Bradford and Tioga Counties, PA
PVR to provide gathering, compression and related services
Range to initially dedicate over 75,000 acres with ongoing active lease acquisition
program within the Area of Mutual Interest (“AMI”)
Gathering system will have over 700 MMcfd of throughput capacity
Total capital investment:
Expect $170 –
$200 million
between 2010 and 2015
(approx. $60 million in
2010)
100% fee-based:
Firm reservation charges
that provide a floor on
returns
Additional volumetric fees
based upon delivered
volumes
Area Infrastructure and Range Positions
Tennessee 300 Line
Connects Gulf coast and
Rockies supply with
northeastern markets
Capability to move 400 MMcfd
of Marcellus production
Transco Leidy Lateral
Connects Leidy storage facility  
with northeastern markets
Capability to move 1.5 Bcfd of
Marcellus production through
physical or backhaul transport
Columbia Gas Transmission / Columbia Gulf
Marcellus Fairway
Areas under development
Texas Eastern Transmission
Tennessee Gas Pipeline
Dominion Transmission
Transcontinental Gas Pipeline
Marcellus Project Provides Significant Fee-Based Growth


22
Distributable Cash Flow
(1)
vs. Distributions
Annual Adjusted EBITDA
(1)
$0
$40
$80
$120
$160
$200
2005
2006
2007
2008
2009
$0
$35
$70
$105
$140
$175
2005
2006
2007
2008
2009
Distributions
DCF
(1)
Adjusted EBITDA and Distributable Cash Flows are non-GAAP financial measures. See Appendix for a reconciliations of these measures to GAAP financial measures
Relatively moderate maintenance capital
expenditure requirements
Target distribution coverage ratio of 1.2x
Target long-term debt / EBITDA ratio of < 3.5x
Growth financed 50% debt / 50% equity
Debt / Adjusted EBITDA
(1)
Average: 2.7x
0.0x
1.0x
2.0x
3.0x
4.0x
2005
2006
2007
2008
2009
Financial Overview


23
Conservative Pro Forma Leverage with Strong Liquidity Profile
Balance Sheet as of June 30, 2010
(1)
Adjusted EBITDA is a non-GAAP financial measure.  See Appendix for a reconciliation of Adjusted EBITDA to operating income and cash flows from operations
(2)
On August 13, 2010, PVR closed on an amended 5 year credit facility of $850 million
(3)
Revolver availability includes adjustment for $1.6 million in letters of credit
Conservative Capitalization
Total Debt
646.5
$     
Partners' Capital
459.4
        
Total Capitalization
1,105.9
$  
LTM Adjusted EBITDA
(1)
190.6
        
Debt / Adjusted EBITDA
3.4x
Debt / Capitalization
58%
Revolver Capacity
(2)
850.0
        
Revolver Availability
(3)
501.9
        


Diversified, Relatively Low-Risk Asset Base
Strategically Located Coal Reserves and Midstream Assets
Stable and Predictable Coal Royalty Business
Solid Balance Sheet and Attractive Yield
Stable Cash Flows and Distribution Coverage
Well
Positioned
to
Capitalize
on
Partnership
Momentum
&
Industry
Trends
Hedged Midstream Business with Growing Fee-Based Volumes
Conclusion: Key Investment Highlights
24


25
Appendix
PVR / PVG Merger
Hedging Strategy
Financial Information


26
PVR and PVG will file a joint proxy statement/prospectus and other documents with the SEC in relation to the merger. Investors
are urged to read these documents carefully when they become available because they will contain important information
regarding PVR, PVG, and the transaction.  A definitive joint proxy statement/prospectus will be sent to unitholders of PVR and
PVG seeking their approvals as contemplated by the merger agreement. Once available, investors may obtain a free copy of the
joint proxy statement/prospectus and other documents containing information about PVR and PVG, without charge, at the SEC’s
website at www.sec.gov. Copies of the joint proxy statement/prospectus and the SEC filings that will be incorporated by reference
in the joint proxy statement/prospectus may also be obtained free of charge by contacting investor relations at 610-975-8204, or
by accessing www.pvresource.com
or www.pvgpholdings.com. PVR, PVG, and the officers and directors of the general partner of
each partnership may be deemed to be participants in the solicitation of proxies from their security holders. Information about
these
entities
and
persons
can
be
found
in
PVR’s
and
PVG’s
Annual
Reports
on
Form10-K
for
the
year
ended
December
31,
2009.
Additional
information
about
such
entities
and
persons
may
also
be
obtained
from
the
joint
proxy
statement/prospectus
when it becomes available.
PVR / PVG Merger Legal Notices
Certain statements by PVR and PVG contained herein that are not descriptions of historical facts are “forward-looking”
statements by PVR and PVG within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of
the Securities Exchange Act of 1934, as amended. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,”
“intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are
intended to identify such forward-looking statements.  These forward-looking statements include, without limitation, the
anticipated benefits and other aspects of the proposed merger, future financial and operating results and expectations and
intentions with respect to future operations and services, approval of the proposed transaction by PVR and PVG unitholders, the
satisfaction of the closing conditions to the proposed transaction, and the timing of the completion of the proposed transaction. 
Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those
expressed or implied by such forward-looking statements.   Many of the factors that will determine PVR’s and PVG's future
results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking
statements, which reflect management’s views only as of the date hereof. PVR and PVG undertake no obligation to revise or
update any forward-looking statements, or to make any other forward-looking statements, whether as the result of new
information, future events or otherwise. These risks as well as other risks, uncertainties and contingencies are discussed in more
detail in PVR’s and PVG's joint press release and public periodic filings with the Securities and Exchange Commission (“SEC”),
including PVR’s and PVG's Annual Reports on Form 10-K for the year ended December 31, 2009 and most recent Quarterly
Reports on Form 10-Q.


27
PVR / PVG Merger -
Transaction Summary
The boards of directors of PVR and PVG have agreed to a merger of the two partnerships in a
tax-free, 100% equity exchange
Terms of the merger were approved by the conflicts committees and boards of PVR and
PVG
The merger is subject to approval by a majority of each of PVR’s and PVG’s unitholders
PVG has agreed to vote its approximate 37.6% interest in PVR units in favor of the merger
PVG unitholders will receive 0.98 PVR limited partnership (“LP”) units in exchange for each
PVG LP unit they own
The merger would result in 38.3 million additional PVR units being issued and the cancellation
of the approximate 19.6 million PVR LP units currently owned by PVG
Following the merger, the former PVG unitholders will own approximately 54% of PVR’s
LP units
The merger would result in PVR owning its General Partner and the cancellation of PVG’s
incentive distribution rights (“IDRs”)
The PVR management team will continue in their current roles
PVR’s unitholders will elect all of the directors of its general partner’s board of directors
beginning in 2011
All three of PVG’s independent directors are expected to join PVR’s board of directors
The transaction is expected to result in dilution of PVR’s distributable cash flow per unit of
approximately 1.0% in 2011
(a)
Thereafter, the transaction is expected to be accretive as the economic benefits of the
merger are realized
(a)
Accretion
/
dilution
calculations
are
based
on
management
assumptions
see
PVR/PVG
merger
presentation
dated
9/22/2010


28
Current Structure
Penn Virginia
Resource Partners, L.P.
(NYSE: PVR)
Public
Unitholders
32.7 MM
Common Units
60.4% LP interest
Penn Virginia
GP Holdings, L.P.
(NYSE: PVG)
Public
Unitholders
39.1 MM
Common Units
100% LP interest
Penn
Virginia
Resource
GP, LLC
100% ownership
2% GP Interest
and Incentive
Distribution Rights
37.6% LP interest
19.6 MM PVR Common Units
Notes:
1)
Chart displays simplified organizational structure
2)
Units outstanding and ownership interests are
rounded approximations
Penn Virginia
Operating Co., LLC
and its subsidiaries


29
Post-Transaction Structure
Penn Virginia
Resource Partners, L.P.
(NYSE: PVR)
Public
Unitholders
71.0 Million
Common Units
100% LP interest
Penn Virginia
Operating Co., LLC
and its subsidiaries
Penn Virginia
Resource GP, LLC
100% (Indirect)
Non-economic GP interest
Notes:
1)
Chart displays simplified organizational structure
2)
Units outstanding and ownership interests are
rounded approximations


30
Expected Merger Benefits
The merger is expected to provide benefits to both PVR and PVG unitholders,
including:
Lower Cost of Capital
Elimination of the IDRs
will reduce PVR’s cost of capital
Lower cost of capital enhances the cash accretion from investments in internal
growth projects and acquisitions
Strengthens PVR’s overall competitive position when pursuing growth
opportunities
Simplified Structure
Provides a capital structure more easily understood by the investing public
Streamlines governance of PVR
Eliminates the potential for conflicts of interest from dual management roles
Reduces
G&A
costs
associated
with
the
elimination
of
one
publicly
traded
entity
Enhanced Investor and Market Profile
Improves transparency for debt and equity investors
Attracts a broader investor base by increasing the public float and trading
liquidity of the market for PVR’s LP units
Provides PVR’s unitholders the right to elect all of the directors of its general
partner’s board of directors
Based on the exchange ratio and upon closing of the merger, PVG
unitholders quarterly cash distributions will increase 18%


31
Derivative Hedging Strategy
PVR is long NGLs
and short natural gas
Active hedge strategy to mitigate commodity price risk
Exposed to “frac
spread”
risk through wellhead purchase
contract and to direct commodity price risk through percent-
of-proceeds contacts
Current and future hedges
2010 hedges are 60% of current price-sensitive volumes
2011 hedges are 58% of current price-sensitive volumes
Target hedging 50-60% of price sensitive exposure out 2 years
Sensitivity to commodity price changes is expected to
decrease as a result of increasing fixed-fee volumes
from the Marcellus Shale, Thunder Creek and
Crossroads


32
$51.2
30.6
-
13.0
(4.8)
1.3
-
(4.6)
$86.7
$104.5
58.2
31.8
(11.4)
(38.5)
(0.2)
-
(14.5)
$129.9
($ in millions)
Year Ended December 31,
2009
2008
2007
2006
2005
2004
Net Income
DD&A
Impairments
Total derivative losses (gains)
Cash settlements of derivatives
Equity earnings from jv’s, net of distributions.
Other
Other CAPEX
Distributable Cash Flow
$34.3
18.6
-
-
-
0.6
-
(0.1)
$53.4
$73.9
37.5
-
13.2
(19.4)
1.3
4.6
(9.5)
$101.6
$56.6
41.5
-
50.2
(17.8)
(0.3)
-
(9.8)
$120.5
$65.2
70.2
1.5
22.7
3.0
(2.5)
-
(8.4)
$151.7
PVR -
Historical Distributable Cash Flow Summary
Distributable Cash Flow Reconciliation


33
(in thousands)
2009
2008
2007
2006
2005
Reconciliation of net income to Adjusted EBITDA:
Net income
$      65,215
$    104,500
$      56,623
$      73,928
$      51,161
Depreciation, depletion and amortization
         70,235
         58,166
         41,512
         37,493
         30,628
Interest expense
         24,653
         24,672
         17,338
         18,821
         14,054
EBITDA
       160,103
       187,338
       115,473
       130,242
         95,843
Impairments
           1,511
         31,801
                -  
                -  
                -  
Equity earnings, net of distributions received
          (2,537)
            (224)
            (285)
           1,317
           1,269
Derivative losses (gains)
         22,700
        (11,357)
         50,163
         13,213
         13,036
Net cash settlements of derivatives
           3,000
        (38,466)
        (17,779)
        (19,436)
          (4,752)
Adjusted EBITDA
$    184,777
$    169,092
$    147,572
$    125,336
$    105,396
Reconciliation of cash flows from operating
activities to Adjusted EBITDA:
Cash flows from operating activities
$    159,972
$    139,176
$    127,824
$    107,344
$      93,712
Changes in operating assets and liabilities
           5,308
           6,529
           2,243
              (60)
            (635)
Non-cash interest expense
          (4,391)
          (2,693)
            (678)
            (769)
          (1,735)
Interest expense
         24,653
         24,672
         17,338
         18,821
         14,054
Equity earnings, net of distributions received
           2,537
             224
             285
          (1,317)
          (1,269)
Derivative gains (losses)
        (22,700)
         11,357
        (50,163)
        (13,213)
        (13,036)
Cash settlement on derivatives
          (3,000)
         38,466
         17,779
         19,436
           4,752
Impairments
          (1,511)
        (31,801)
                -  
                -  
                -  
Other
            (765)
           1,408
             845
                -  
                -  
EBITDA
       160,103
       187,338
       115,473
       130,242
         95,843
Impairments
           1,511
         31,801
                -  
                -  
                -  
Equity earnings, net of distributions received
          (2,537)
            (224)
            (285)
           1,317
           1,269
Derivative losses (gains)
         22,700
        (11,357)
         50,163
         13,213
         13,036
Net cash settlements of derivatives
           3,000
        (38,466)
        (17,779)
        (19,436)
          (4,752)
Adjusted EBITDA
$    184,777
$    169,092
$    147,572
$    125,336
$    105,396
Year Ended December 31,
PVR -
Historical Adjusted EBITDA Summary
Reconciliation of Adjusted EBITDA